1 December 2005
Digital control lets power flow
Canadian thermal generating station gets seamless migration.
By Jeff Vincent
When management at Newfoundland & Labrador Hydro's (NLH) Holyrood Thermal Generating Station learned support for its legacy distributed control system would end in 2005, they began planning an upgrade to a modern, digital control system almost immediately. The Holyrood plant powers about a third of the island's grid, and a reliable distributed control system is critical for safe, reliable, and efficient operation. Operating the plant with obsolete controls is not an option.
"We were especially interested in the fault tolerance functionality of digital control systems," said Jeff Vincent, project and maintenance manager at Holyrood. "Our system cannot tolerate a single point of failure. A loss of one or more generating units could result in under-frequency load shedding on the power system, which would leave several customers without power. Downtime is unacceptable."
Plant management first evaluated the migration the DCS OEM offered. Although this would have allowed retaining existing cabinets, field wiring, and terminations, it would also require retaining aging I/O cards. During their evaluation of alternative solutions, they fitted I/O cards to the existing wiring and terminals.
Blending old and new
They installed the distributed control operator interface equipment into existing consoles, with minor modification of existing systems, including upgrading monitors and keyboards.
With the control hardware infrastructure unspoiled, NLH engineers could focus on migrating existing control logic and data and developing new processes to leverage the plant's new digital control functionality.
To begin the migration, the company's engineers gathered software from the existing DCS, including the operator interface screen software files, database and control files, control logic drawings, P&IDs, and verbal descriptions of plant systems.
"Often the new control software language did not map well to the old DCS structures," Vincent said. "In some cases, we chose to redesign the application logic to take advantage of new features afforded us by the digital controls and the new I/O." Likewise, they had to map the historians, reports, and performance monitoring logic to the new logic.
Transitioning operator interface
The plant gave much consideration to the operator interface—the most visible part of the system and the place major informational exchange occurs between human users and applications. A senior member of the operations staff supervised migration of all screen graphics to the new DCS.
"Our existing graphics had gone through years of incremental changes to optimize them to our exact operational needs," Vincent said. The group had to develop, document, and test new graphic displays. "Depending on the screen's complexity, this would take several hours. Being sure new versions of existing displays presented themselves and interacted with the operator in a beneficial manner was a major area for attention and review," he said. From a hardware point of view, the group's existing operator consoles changed little to accommodate the new monitors and keyboards.
Testing and training
The system was ready for a switchover with infrastructure, applications, and interfaces in place. The physical switchover included unplugging the old cards and replacing them with the new, but ensuring a seamless switchover required thorough testing and training.
Holyrood employees prepared for the installation and transition through customized training. After that, they followed these construction and commissioning procedures:
- Install and test control system software, including the DCS application itself and the operator interface.
- Test and debug the installed DCS equipment.
- Confirm all motor start/stop and protection logic.
- Verify control system circuitry and I/O (loop tests).
- Test all interfaces to other control systems.
- Calibrate field devices as required.
- Test other mechanical equipment as required.
- Run process and tune process controls.
Now the physical switchover could occur, allowing two weeks for each unit.
Vincent said the I/O cards had the same form factor as their legacy DCS controls, so their migration retained all field wiring and terminations even though they replaced the rest of the system.
More reliable controls
Simply replacing old with new brings a direct benefit in the reliability of the system. It also lowered DCS hardware replacement costs. One of the best reliability improvements was the process tuning on all critical loops during the startup. New DCS screens improved operator efficiency, incorporated indication and control for a particular system on a single screen, and enabled the operator to make decisions and quickly see the result of actions. The screen looks like the piping and instrumentation (P&ID) diagrams, with which the operators are already very familiar.
Simplified software maintenance
The new DCS runs on a Windows XP operating system, which simplified software maintenance and modification. It was also familiar to operators and technical staff. The programming environment makes it easier for developers to incorporate additional program functionality as techniques and languages advance.
From the I/O cards, through the networks, to the controllers and servers, all components are more capable of indicating a problem, as well as identifying the problem. Increasing self-diagnostic information available from the DCS and its components makes it easier for operators and technologists to troubleshoot.
The plant also got a complete set of as-built functional logic drawings to help with future modifications. And given Holyrood now has a modern digital control systems, they can modify systems cost effectively as operations change or grow. Control logic, application data, hardware, and user interface are integrated yet independent, so they can implement advances in control processes, computing hardware, and user interface without facing a complete system upgrade ever again.
Behind the byline
Jeff Vincent is maintenance manager and project manager for DCS upgrades at Newfoundland & Labrador Hydro in St. John's, Newfoundland, Canada.
Best investment first
Retrofitting pulp and paper mills to maintain world class status
By Ellen Fussell Policastro
When a controls engineer in the cooking area of a pulp mill submitted a project to replace his old equipment, he knew he had a certain amount of money to replace equipment but didn't look into adding optimization possibilities. "The process and field optimization sides are where you can do asset management with field devices," said Ed Schodowski, global sales director in pulp and paper at Emerson Process Management in Rochester Hills, Mich. "All these possibilities were in that project, but since the engineer didn't see it as his objective, he didn't take advantage of any of them."
The pulp and paper industry has a history of low return on capital projects, especially when plants don't foresee the potential for technology features when replacing old equipment. Historically, manufacturers would cite reasons for replacing equipment, "just because it's old," Schodowski said. And if they don't take advantage of optimizing the process, they get a lower return on projects, he said. "In the past, people would come to you and buy automation equipment because they were putting in a new power boiler," he said. "Today nobody is putting in anything new. So they're looking at ways with smaller capital investment to optimize productivity of mills that haven't been shut down. They're the survivors, and they need to look at ways to continuously improve their productivity."
Schodowski said huge opportunities exist that allow manufacturers to make "leap-frog steps" in plant operation that most aren't taking advantage of. This is where opportunity mapping comes in handy.
Energy is a huge thing in pulp and paper, and the opportunity mapping procedure identifies the highest return projects and possibilities in an automation process. It also identifies liability and systems with no spare parts that could potentially take a site down. "We look at vintage of equipment and modern equipment involved that isn't optimized," Schodowski said. "We found high-return projects on process areas that had just installed new controls equipment but never took advantage of horse power like advanced process control features."
Schodowski's team also found a new control system installed on a lime kiln with no multiple predictive control functionality (MPC) in the process. "They had this capability but never used it with the lime kiln project. Our engineers optimized all the parameters and ran the gas at the lowest level to get the quality of lime required at the kiln." If that happens in manual mode, operators sometimes turn the gas up to make sure they have plenty of heat to get the job done, thus not optimizing fuel usage. With most lime kiln projects Schodowski works on, he typically sees $500,000 a year in natural gas savings.
"We're seeing the same thing in multi-fuel burners where they burn bark and tires," he said. Optimizing those types of boilers brings significant return on investment and eliminates the need for burning natural gas in the mill as well.
Best investment retrofit
In retrofitting control systems, manufacturers should make their first investment where they can reap the highest returns. And since paper mills tend to do their retrofit projects in stages (process unit by process unit), it makes sense to do the highest return project first to get the returns up front so it can supplement future projects, Schodowski said. "I've seen mills where the strongest or loudest superintendent gets the automation," he said. "And it may not be the right place to do the retrofit project; it may just be the loudest voice. And the other area has the higher return." That's why manufacturers should asses the whole mill to see which areas have the biggest potential for return.
Should engineers install equipment based on the fact the system is old and they can't get spare parts or there might be reliability issues? Or should they look at the whole process and figure out a way to improve the productivity of the process before they begin the automation project?
The paradox is mill engineers sometimes figure it's easier or low risk to go back and replace something the same way it's already installed. But Schodowski said the real returns of doing automation are taking the extra step of asset optimization. "That takes understanding the process and how you'll get that return and what you'll do differently in terms of standard operating procedures," he said. "It takes a skilled eye to see where the bottlenecks are and the obstacles to design the control strategies to operate more efficiently, save energy, and ultimately improve the process.
Using Ethernet with legacy systems
By Helge Hornis, Ph.D.
Ethernet has clearly made it to the plant floor. This creates new opportunities for improved diagnostics and increased system availability. Those are just two reasons why people like Ethernet and new products support it. But what if one has an existing installation that employs legacy products that only offer an RS232 connection? Or how about getting barcode scanners to interface with a PLC that support Modbus/TCP, the de-facto standard Ethernet protocol?
Getting RS232 devices to talk Ethernet is possible with device server technology. The problem has been that early device servers were not necessarily designed for industrial applications; they didn't support Modbus/TCP, and the available diagnostics were usually well below what industrial users require.
Device server technology, however, is adapting and is now available with Modbus/TCP and powerful diagnostics functions. Modbus/TCP is a multi-client protocol allowing a PLC to access the data. At the same time, a SCADA system or second PLC can get a copy of the data for the purpose of visualization.
Newer device server technology also enables Web-based configuration and diagnostics status information. But SCADA and other diagnostic software packages require a more machine-readable format than is offered with Web-based configurations. Ethernet devices designed for industrial applications offer exactly that. Certain device servers offer features whereby vital status information travels unsolicited at regular intervals.
A barcode scanner with RS232 connects to a device server. Scanned data (334539) travels via port 3000. Alternatively, a PLC can connect to the MODBUS/TCP port and receive the same information. Multiple simultaneous clients can get this information. This allows visualization on a SCADA system. Up-to-the-second status information goes via a status port to a PC-based monitoring application. From here, pager and e-mail notification is possible.
Behind the byline
Helge Hornis, Ph.D., is intelligent systems manager at Pepperl+Fuchs in Twinsburg, Ohio.